August 7, 2012
Jennifer Thompson
Accounting Branch Chief
Division of Corporation Finance
U.S. Securities and Exchange Commission
100 F Street, N.E.
Washington, D.C. 20549
Re: GenOn Energy, Inc.
Form 10-K for the Year Ended December 31, 2011
Filed February 29, 2012
File No. 1-16455
GenOn Americas Generation, LLC
Form 10-K for the Year Ended December 31, 2011
Filed February 29, 2012
File No. 333-63240
GenOn Mid-Atlantic, LLC
Form 10-K for the Year Ended December 31, 2011
Filed February 29, 2012
File No. 333-61668
Dear Ms. Thompson:
On behalf of GenOn Energy, Inc., we have the following response to your comment letter dated July 25, 2012 relating to the above referenced filings.
For your convenience, we have included the comment of the staff (the Staff) of the Securities and Exchange Commission (the Commission) below in bold followed by GenOn Energy’s corresponding response.
GenOn Energy, Inc. Form 10-K for the Fiscal Year Ended December 31, 2011
General
1. Please note that the following comments address accounting practices, presentation and disclosure matters of GenOn Energy, Inc. and subsidiaries on a consolidated basis. In our interest to reduce the volume of comments, we have not addressed each subsidiary with a separate comment if applicable to their facts and circumstances. Please note that if you agree to a revision, we would also expect a concurrent change be made in the subsidiary level financial statements to the extent material. Please confirm to us your agreement with this objective.
Response: We agree with your objective.
Financial Statements, page F-1
Notes to Consolidated Financial Statements, page F-6
1. Description of Business and Accounting and Reporting Policies, page F-6
Funds on Deposit, page F-12
2. Please confirm that all balances included within your “Funds on deposit” line item represent funds that are legally restricted as to withdrawal. We note, for example, your disclosures on page F-85 that the $166 million of Gen-On Mid-Atlantic restricted cash at December 31, 2011 relates to cash “reserved” for liens that “are interlocutory only and will not become final unless and until” a plaintiff “is successful in prosecuting its contractual claims.” Please clarify why this “reserved” cash balance qualifies for separate classification on your balance sheet.
Response: The funds on deposit line item includes restricted cash, deposits with brokers, cash collateral posted and cash deposits posted to guarantee some of our environmental obligations. To ensure there was adequate transparency to the readers of our 2011 Form 10-K relating to the accounting policy regarding funds on deposit, in addition to the disclosure of the funds on deposit table in Note 1, Description of Business and Accounting and Reporting Policies on page F-12, we disclosed the cash collateral posted for energy trading and marketing and other operating activities, which are included in funds on deposit, in Note 10(b), Commitments and Contingencies, Cash Collateral on page F-72 and in Liquidity and Capital Resources—Cash Collateral, Letters of Credit and Surety Bonds on page 85.
GenOn Mid-Atlantic, LLC leases a 100% interest in both our Dickerson and Morgantown baseload units and associated property. In 2011, Stone & Webster, Inc. (Stone & Webster), the engineering, procurement and construction (EPC) contractor for the scrubber projects at the Chalk Point, Dickerson and Morgantown generating facilities, filed three suits against us in the United States District Court for the District of Maryland. Stone & Webster claimed that it had not been paid in accordance with the terms of the EPC agreements for the scrubber projects and sought liens against the properties. At December 31, 2011, $166 million in interlocutory liens were outstanding.
In accordance with GenOn Mid-Atlantic, LLC’s lease documentation, we are required to set aside adequate cash reserves for any liens, including those which are being contested in good faith by appropriate proceedings. The provisions of the lease documentation apply to both leased and non-leased properties. Therefore, at December 31, 2011, $166 million was classified as funds on deposit pursuant to GenOn Mid-Atlantic, LLC’s lease documentation.
2. Merger, page F-17
3. We note that you finalized the Mirant and RRI Energy purchase price allocation in 2011. Please address the following items:
· Please clarify why significant adjustments to your initial purchase price allocation were necessary. In doing so, tell us the intervening events that occurred and/or
information that was received from the initial closing of the merger to the finalization of the purchase price and clarify why such information was not available at an earlier date.
Response: Prior to the completion of the merger on December 3, 2010, both RRI Energy, Inc. and Mirant Corp. were unable to share certain proprietary information with regards to our fundamental views, which are used to develop estimated cash flows for our facilities, of the business as a result of United States antitrust laws. Only after the completion of the merger was GenOn management able to begin to establish its fundamental views on future capacity and energy prices, environmental and maintenance expenditures and other cash flows impacting the business, which were knowable at the acquisition date. These post-merger determinations affected the assessments of fair value of significant assets and liabilities for which provisional amounts had been recognized in the initial purchase price allocation.
In connection with the merger, we engaged advisors to assist in the valuation of the acquired assets and liabilities. Throughout the process, we provided inputs, cash flows and other data to our advisors. During the third quarter of 2011, we received an updated, but not final, draft of the valuation report from our advisors, which indicated differences significant enough to warrant adjustments to our provisional fair values as a result of revisions to knowable facts and circumstances that existed at the acquisition date. Property, plant and equipment fair value decreased by approximately $49 million as a result of revisions to and more detailed analysis of assumptions around long-term prices and environmental impacts which were derived from proprietary fundamental models and incorporated in our discounted cash flows subsequent to the completion of the merger. In addition, the fair value of our out-of-market contracts (including natural gas transportation contracts, operating leases on certain generating facilities and other contracts), which were classified as long-term liabilities, increased a net $80 million from the preliminary purchase price allocation to the estimate in the third quarter of 2011 primarily as a result of: (a) changes in the modeling assumptions for natural gas transportation contracts, specifically increased correlation coefficients between receipt and delivery points as compared to the original assumptions, and reduced receipt point price expectations for some of these contracts as a result of incorporating price constraint expectations within the broader market delivery zones; and (b) changes to inputs and assumptions for operating leases on certain generating facilities, such as discount rates and estimated useful lives. These changes were based on refinement and clarity of knowable facts at the acquisition date.
During the fourth quarter of 2011, we supplied some revised estimates and assumptions relating to two facilities to our advisors. This was to consider further developments given knowable facts and circumstances at the acquisition date. Also, during the first quarter of 2012 (and prior to the issuance of our annual 2011 financial statements), we received the final valuation report from our advisors and this resulted in the final revisions to our preliminary purchase price allocation. Property, plant and equipment fair value further decreased $20 million as a result of additional reductions in certain plant values upon further clarity around emission investment requirements anticipated in future years for which the facts existed at the acquisition date. Additionally, the fair value of our out-of-market contracts, which were classified as long-term liabilities, increased $33 million as a result of further clarity around the potential effect of environmental investment requirements at one of our leased facilities.
· You state that your revisions to the provisional allocation resulted in an increase to your net loss of $7 million for the nine months ended September 30, 2011. Please explain why your adjustments resulted in an increase, not a decrease, to net loss during that period.
Response: Final revisions recorded in the fourth quarter of 2011 to the provisional purchase price allocation resulted in an increase to our net loss of $7 million for the nine months ended September 30, 2011. The increase in net loss represents increase in depreciation expense related
to the final valuation adjustments to our property, plant and equipment, specifically the reduction in estimated useful lives, which were recorded during the three months ended December 31, 2011.
· Please reconcile the 2011 quarterly net income (loss) amounts presented in your quarterly financial data footnote on page F-83 to the amounts reported in your 2011 Forms 10-Q filed during the year. In doing so, tell us how the $7 million adjustment for the nine months ended September 30, 2011 is reflected in footnote 15 and clarify if the September 30, 2011 year to date net loss should be $282 million, as reported in your third quarter Form 10-Q, or $289 million, as computed from footnote 15 and your individual 2011 Forms 10-Q.
Response: The following table reconciles the 2011 quarterly net loss amounts which were presented in our quarterly financial data footnote on page F-83 to the amounts reported in our 2011 Forms 10-Q filed during the year.
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| As Reported |
| Interim Revisions |
| Final Revisions |
| As Reported |
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| (in millions) |
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Three months ended March 31, 2011 |
| $ | (113 | ) | $ | 1 |
| $ | 1 |
| $ | (111 | ) |
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Three months ended June 30, 2011 |
| (138 | ) | 6 |
| (6 | ) | (138 | ) | ||||
Six months ended June 30, 2011 |
| (251 | ) | 7 | (1) | (5 | ) | (249 | ) | ||||
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Three months ended September 30, 2011 |
| (38 | ) | not applicable |
| (2 | ) | (40 | ) | ||||
Nine months ended September 30, 2011 |
| (282 | ) | not applicable |
| (7 | )(2) | (289 | ) | ||||
(1) Represents a decrease in net loss as a result of interim revisions to the provisional purchase price allocation and is disclosed in Note 2, Merger in our 2011 third quarter Form 10-Q.
(2) Represents an increase in net loss as a result of the final revisions to the provisional purchase price allocation and disclosed in Note 2, Merger in our 2011 Form 10-K.
Inventories, page F-12
4. We note your coal inventory balance was $229 million at year end and at March 31, 2012. We further note your disclosures on page 35 of your March 31, 2012 Form 10-Q that the decrease in coal-fired generation has led to significant coal inventories and, since your Mid-Atlantic facilities are at their maximum available storage capacity, you have issued notices of force majeure under your coal contracts that are being disputed by your suppliers. In light of these developments, as well as the anticipated deactivation and layup of several of your coal plants, the continued decline in natural gas prices, which negatively impacts the energy gross margins of your baseload coal units, and the movement toward clean air and “green” initiatives, please quantify for us the coal-specific lower of cost or market value adjustments you recorded during the most recent annual and quarterly periods presented and clarify why further reserves were not necessary. Also tell us how your lack of storage facilities and force majeure notices impacted your accounting for coal contracts and commitments, and tell us and quantify in your disclosures the total commitments under your coal supply contracts as well as all coal-specific derivatives assets and liabilities.
Response: During 2011 and the quarter ended March 31, 2012, we recorded lower of average cost or market valuation adjustments related to coal inventories of $10 million and $46 million, respectively. The lower of average cost or market valuation adjustment is determined by comparing end of the reporting period book value (which is computed using weighted average cost method) and market value. Market value is determined based on closing prices for related market indexes plus transportation costs. Inventory adjustments are recorded when book value exceeds market value for each reporting period end.
Our coal commitments, which are disclosed on an annual basis as part of our fuel commitments (in Note 10, Commitments and Contingencies, page F-68 for the December 31, 2011 amounts) are as follows:
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| 2012 |
| 2013 |
| 2014 |
| |||
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| (in millions) |
| |||||||
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At December 31, 2011 |
| $ | 636 |
| $ | 275 |
| $ | 31 |
|
At March 31, 2012 |
| 472 | (1) | 288 |
| 58 |
| |||
(1) Represents commitments from April 2012 to December 2012.
A significant number of our coal contracts are recorded at fair value and reflected in our balance sheets as derivative contract assets or liabilities. At December 31, 2011, the fair value of coal included in derivative contract assets and derivative contract liabilities was $8 million and $79 million, respectively. At March 31, 2012, the fair value of coal included in derivative contract assets and derivative contract liabilities was $6 million and $118 million, respectively.
In May 2010, we concluded that we could no longer assert that physical delivery was probable for many of our coal contracts. As a result, we were required to apply fair value accounting for these contracts beginning in the quarter ended June 30, 2010 and prospectively. Therefore, for 2011, only certain coal contracts with one supplier were documented with a normal purchase, normal sale (NPNS) exception election. This NPNS status was maintained for the quarter ended March 31, 2012 based on valid operational reasons.
In April 2012, we issued notices of force majeure under the respective coal contracts as it was impossible for us to take coal at such facilities. In May 2012, as we began excising tonnage, we could no longer assert that physical delivery was probable for the remaining coal contracts for which we had elected the normal purchase exception. As such, the normal purchase exception was removed, and we recorded the fair value of these contracts on the balance sheet at June 30, 2012 as a net derivative liability of $49 million and immediately recognized that amount in earnings as unrealized losses in cost of fuel, electricity and other products.
In future filings, commencing with the Form 10-Q for the second quarter of 2012, we will add a sub-footnote to our disclosure of Fair Value of Derivative Instruments and Certain Other Assets, the fair value measurements of financial assets and liabilities by class, to indicate that the Level 3, asset management fuel contracts primarily relate to coal.
4. Financial Instruments, page F-23
5. Footnote (2) to your table on page F-24 indicates that the settlement value of fuel contracts classified as inventory are excluded from realized gains (losses) on derivative financial instruments effective January 1, 2011. Please explain to us in greater detail the nature of this change and, if applicable, the related accounting guidance you followed.
Response: In May 2010, we concluded that we could no longer assert that physical delivery was probable for many of our coal contracts. As a result, we were required to apply fair value accounting for these contracts beginning in the quarter ended June 30, 2010 and prospectively. During this same period, we had increased physical residual oil activity, which also receives fair value accounting. As these physical coal and oil contracts began to settle in the second half of 2010, we noted that including the settlement value of fuel classified as inventory could give rise to unexplained differences between the change in fair value of the contracts and their settlement values.
As part of our merger integration and after reviewing the guidance in ASC Topic 815, we determined the literature did not define realized gains and losses for purposes of this disclosure and that either presentation was acceptable under United States generally accepted accounting principles. Therefore, beginning in 2011, we concluded that to exclude the fuel inventory settlements would be a clearer and more meaningful presentation of the change in fair value and the settlements of these contracts. Additionally, because of changes in commodity prices and the myriad instruments existing in our derivative portfolio at any given time, the amounts reflected as realized gains and losses are not comparable from period to period. As such, we concluded that quantifying the amount included for the partial year of inventory settlements in this disclosure for 2010 was not likely to be meaningful to investors. In addition, it is important to note that this change did not impact the statement of operations.
5. Long-Lived Assets, page F-34
6. We note your discussion throughout your document and in footnote 17 that you plan to retire, deactivate, mothball and/or place in layup several of your generating facilities in upcoming years. We further note that the aggregate carrying value of property, plant and equipment and materials and supplies inventory for these facilities is $212 million and $53 million, respectively, as of year-end. Please address the following comments:
· Please quantify for us property plant and equipment and materials and supplies inventory by facility.
Response: The table below includes property, plant and equipment, net and material and supplies inventory values at December 31, 2011 related to the generating facilities that we plan to retire, deactivate, mothball and/or place in long-term protective layup.
Generating Facility |
| Property, Plant and |
| Materials and Supplies |
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| (in millions) |
| ||||
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Niles |
| $ | — |
| $ | 3 |
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New Castle |
| — |
| 4 |
| ||
Elrama |
| — |
| 6 |
| ||
Avon Lake |
| 59 |
| 5 |
| ||
Portland |
| 88 |
| 16 |
| ||
Titus |
| 30 |
| 6 |
| ||
Glen Gardner |
| 8 |
| — |
| ||
Shawville |
| 27 |
| 13 |
| ||
|
| $ | 212 |
| $ | 53 |
|
· We note at the top of page 50 that you expect to incur some charges beginning in the first quarter of 2012 related to the deactivations of these facilities. Please tell us whether any impairments were recorded for these facilities during the most recent annual and quarterly periods presented and, if no assets were impaired, explain the factors justifying such a conclusion. If you tested any assets related to these generating facilities for impairment under ASC 360-10-35, explain how you treated restoration and environmental exit costs in your impairment tests and clarify if the tests yielded any material assets at risk of impairment. Also provide us with further details regarding how you assessed the supplies and inventory balances of these facilities for lower of cost or market charges.
Response: We did not record any impairments for the generating facilities that are identified above during 2011 or the three months ended March 31, 2012. All of the above mentioned generating facilities were recorded at their estimated acquisition date fair values as a result of the merger. The useful lives used in the analysis for plant fair value assumptions at December 3, 2010 were based on anticipated environmental regulations and were the same as the conclusions reached by management during the first quarter of 2012 regarding the evaluation of retirement dates for the above mentioned generating facilities. Therefore, there were no events or changes in circumstances which indicated that carrying amounts may not be recoverable per ASC 360-10-35-21 from the date of the merger through the first quarter of 2012.
We made and announced the decision to mothball, retire or place in long-term protective layup the above mentioned generating facilities in February 2012. In addition, the publication by the Environmental Protection Agency of the maximum achievable control technology (MACT) regulations occurred in the Federal Register on February 16, 2012. We account for materials and supplies inventory using the average cost method. Provision for potentially obsolete materials and supplies inventory is recorded based on management’s analysis of inventory levels and historical usage. In determining an estimated materials and supplies inventory reserve, we performed a study evaluating the inventory at the generating facilities subject to deactivation as well as analyzing the
existing inventory at our facilities to remain in operation. The evaluation process included (a) estimating materials and supplies inventory usage at the facilities prior to their deactivation dates, (b) identifying materials and supplies inventory that could be utilized at some of our other generating facilities and (c) estimating materials and supplies inventory that could be sold to third parties and at an estimated percentage of cost. An excess materials and supplies inventory reserve was recorded in the period in which we made the decision to mothball, retire or place in long-term protective layup certain generating facilities, as well as the period in which significant operational changes were planned as a result of such decisions, i.e., the first quarter of 2012.
· Please tell us how your deactivation plans have impacted or are expected to impact your depreciation methodologies and estimates. Please specify which facilities you expect to temporarily idle and which facilities you intend to permanently close.
Response: The previously announced deactivation plans did not significantly impact our depreciation methodologies and estimates. The estimated useful lives of these generating facilities were established in connection with purchase accounting and generally were consistent with the announced deactivation dates. We adjusted our estimated depreciable lives in the first quarter of 2012 in conjunction with the decision and announcement of the deactivations for the facilities below, which did not have a $0 net book value. The table below summarizes (a) generating facilities that we expect to temporary idle and permanently close; (b) retirement dates for the facilities assumed during purchase accounting and (c) announced deactivation dates for the facilities.
Generating Facility |
| Retirement Dates |
| Announced Deactivation Dates |
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Niles Unit 2 (1) |
| December 2015 |
| Retired June 2012 |
|
Elrama Units 1-3 (1) |
| December 2017 |
| Mothballed June 2012; Retire March 2014 |
|
Niles Unit 1 (1) |
| December 2015 |
| Retire October 2012 |
|
Elrama Unit 4(1) |
| December 2017 |
| Mothball October 2012; Retire March 2014 |
|
Portland |
| December 2014 |
| Retire January 2015 |
|
New Castle (1) |
| December 2017 |
| Retire April 2015 |
|
Avon Lake |
| December 2015 |
| Retire April 2015 |
|
Titus |
| December 2015 |
| Retire April 2015 |
|
Shawville |
| December 2015 |
| Place in long-term protective layup in April 2015 |
|
Glen Gardner |
| December 2015 |
| Retire May 2015 |
|
(1) At December 31, 2011, these generating facilities/units were assigned $0 net book value at the acquisition date.
· Please tell us if you anticipate presenting the results of any generating facilities or related operations within discontinued operations. In doing so, tell us whether or not you consider each generating facility to be a component of an entity, as defined in ASC 205-20-20.
Response: ASC 205-20-20 states that a component of an entity comprises operations and cash flows that can be clearly distinguished, operationally and for financial reporting purposes, from the rest of the entity. A component of an entity may be a reportable segment or an operating segment, a reporting unit, a subsidiary, or an asset group. Asset group is the unit of accounting for a long-lived asset or assets to be held and used, which represents the lowest level for which
identifiable cash flows are largely independent of the cash flows of other groups of assets and liabilities.
In performing the discontinued operations analysis (which is more fully discussed below), we determined that the individual generating facilities represent the lowest level for which identifiable cash flows are available and therefore are considered to be a component of an entity.
ASC 205-20-45-1 states that the results of operations of a component of an entity that either has been disposed of or is classified as held for sale shall be reported in discontinued operations if both of the following conditions are met: (a) the operations and cash flows of the component have been (or will be) eliminated from the ongoing operations of the entity and (b) the entity will not have any significant continuing involvement in the operations of the component after the disposal transaction.
ASC 205-20-55-4 through 205-20-55-8 guidance was considered in determining whether operations and cash flows of these generating facilities are (or will be) eliminated from ongoing operations. The generating facilities that we expect to retire, mothball or place in long-term protective layup are located in the PJM and MISO electric transmission regions and are included in our Eastern PJM and Western PJM/MISO segments. We determined that continuing cash flows are expected to be generated from the sale of electricity, capacity, ancillary and other energy services in the Eastern PJM and Western PJM/MISO operating segments. The continuing cash flows result from a migration or continuation of activities in the PJM and MISO regions. During 2011, approximately 65% and 56% of our operating income was attributable to our Eastern PJM and Western PJM/MISO operating segments, respectively. This conclusion is consistent with guidance in ASC 205-20-55-7(a) which states that significant cash inflows are expected to be recognized by the ongoing entity as a result of a migration of revenues from the disposed component after the disposal transaction. There is a presumption that if the ongoing entity continues to sell a similar commodity on an active market after the disposal transaction, the revenues and costs would be considered a migration.
Based on the above analysis, we do not anticipate presenting the results of these generating facilities within discontinued operations.
7. We note your disclosures on page F-37 that you recorded a $32 million charge to operations and maintenance expense and corresponding liabilities during fiscal 2010 associated with your commitment to reduce particulate emissions related to your Potomac River Generating Facility (“PEPCO”). We further note that you intend to reverse this entry once PEPCO consents to the removal from service of this facility. Please clarify for us why it was necessary to you record a charge during fiscal 2010 related to this commitment.
Response: In July 2008, the City of Alexandria, Virginia (in which the Potomac River generating facility is located) and GenOn Potomac River entered into a settlement agreement (July 2008 Agreement). Under the terms of the July 2008 Agreement, GenOn Potomac River would be allowed to complete a smokestack reconfiguration and return five units to operation upon the issuance of a two stack permit by the Air Pollution Board. In return, GenOn Potomac River had to escrow $34 million into an account to be used solely for capital improvements to achieve fine particulate matter emissions reductions. Pursuant to the July 2008 Agreement, we deposited $34 million in an interest bearing escrow account. In 2008, based on our analysis, the required capital expenditures of $34 million were more than offset by the incremental revenue estimated to be gained by returning the units to operation. During 2009, we spent approximately
$2 million on a street sweeper and other fugitive dust controls in accordance with Phase I of the Project and engineering costs on Phase II of the Project (as defined by the July 2008 Agreement).
During the fourth quarter of 2010, we recorded the impairment of the Potomac River generating facility, which reduced its carrying value to its estimated fair value of approximately $1 million. In conjunction with the impairment of the Potomac River facility, we evaluated the nature of the $32 million commitment pursuant to ASC 330-10-35-17 and 18. At that point in time, the current expectation was that the funds would be used for the installation of baghouses or other fine particulate matter emissions control technology at the facility. In addition, the July 2008 Agreement required that if the committed funds were not used for installation of additional air pollution controls at the Potomac River facility, that the City of Alexandria, Virginia could use the funds for air quality enhancements at other locations in the City at the City’s discretion. As a result of the impairment of the Potomac River generating facility, we recorded $32 million in operations and maintenance expense and corresponding liabilities associated with our commitment to reduce fine particulate matter emissions, because the committed capital investment would not be recovered in future periods based on the projected cash flows of the Potomac River generating facility.
In August 2011, we entered into an amendment to the July 2008 Agreement with the City of Alexandria, Virginia to permanently remove from service our Potomac River generating facility (August 2011 Agreement). The August 2011 Agreement amends the July 2008 Agreement and provides for the retirement of the Potomac River generating facility on October 1, 2012, subject to the receipt of all necessary consents and approvals, including a finding by PJM that Potomac River is not needed for reliability. In addition, the August 2011 Agreement terminates our obligation to invest $34 million into capital improvements for the implementation of fine particulate matter emissions control and technology. Upon retirement of the Potomac River generating facility, all remaining funds in the escrow account ($32 million) established under the July 2008 Agreement will be distributed to us, provided that, if the retirement of the facility occurs after January 1, 2014, $750,000 of such funds will be paid to the City.
In September 2011, we received notification from PJM that Potomac River will not be needed for reliability and in June 2012 Potomac Electric Power Company gave its consent. As a result, the Potomac River generating facility will be retired on October 1, 2012. Upon receipt of all necessary approvals, we reversed $31 million of the previously recorded obligation under the 2008 Agreement with the City of Alexandria and recognized a reduction in operations and maintenance expense during the three months ended June 30, 2012. The remaining $750,000 will be recognized as a reduction in operations and maintenance expense when the cash is returned from escrow.
9. Stock-Based Compensation, page F-62
Time-based Restricted Stock Units and Performance-based Restricted Stock Units, page F-66
Performance-based Awards, page F-66
8. We note here and on page F-64 that certain of your restricted stock units are linked to the 2011 short-term incentive plan of performance goals, with performance measured at the end of the first year to determine a multiplier between 0% and 200% of the targeted grant. We further note that in February 2012, the performance multiplier was determined to be 174%. Please tell us and expand your disclosure to explain how you account for your
performance-based restricted stock units, including how your multiplier determines the compensation expense recognized related to these issuances.
Response: Vesting of our performance-based restricted stock units is subject to the satisfaction of a service condition and the fulfillment of a performance condition. The awards are classified and accounted for as equity awards in accordance with ASC 718-10-55-66. The number of units that are earned is dependent on the performance condition achievement level (performance multiplier) and can range from 0% to 200% of the target award. A sliding scale of achievement is used to compute the total compensation cost expected to be recognized. We recognize compensation expense for the outcome that is probable and the probability assessment is updated at each reporting period. Our final measure of compensation expense is based on the grant-date fair value for the outcome that actually occurs.
Subject to the service condition, the performance-based restricted stock units vest in three equal installments with the first installment vesting on the date the performance achievement level is approved by the Compensation Committee of the Board of Directors (the Determination Date). The remaining two-thirds vest ratably on the first and second anniversaries of the Determination Date. Compensation expense is amortized on a straight-line basis over the requisite service period for the entire award.
In the 2012 Form 10-K, we will add the following disclosure with respect to how we account for performance-based restricted stock units with “XX” for placeholders for specific future items:
Performance-based awards. In 2012, we granted XX million performance-based restricted stock units to certain employees. These restricted stock units are linked to the short-term incentive plan performance goals, with performance measured at the end of the performance period to determine a multiplier between 0% and 200% of the targeted grant. We recognize compensation expense for the outcome that is probable and the probability assessment is updated at each reporting period, with the final measure based on the grant-date fair value for the outcome that actually occurs. In [specific month] of 2013, the performance multiplier was determined to be XX%. Vesting of our performance-based restricted stock units is subject to the satisfaction of a service condition and the fulfillment of a performance condition. These restricted stock units vest in three equal installments with the first installment vesting on the date the performance achievement level is approved by the Compensation Committee of the Board of Directors (the Determination Date), and the subsequent installments vesting on the first and second anniversaries of the Determination Date.
10. Commitments and Contingencies, page F-67
(a) Commitments, page F-68
REMA Operating Leases, page F-69
9. We note your plans to place the coal-fired units at the Shawville facility, which is leased, in long-term protective layup in April 2015. We further note that you will continue to evaluate your options under the lease, including termination of the lease for economic obsolescence and/or keeping the facility in long-term protective layup during the term of the lease. We also note on page F-69 that the Shawville lease is through 2026 and you expect to make payments through that date. In light of your plans to place Shawville in protective layup while continuing to make payments, we believe that additional disclosure with respect to this facility would be beneficial to investors. As such, please disclose the amount of lease
payments expected to be paid for Shawville through 2026. Please also disclose, if known, the approximate amount of annual maintenance costs that will be incurred during the layup period.
Response: GenOn REMA LLC (REMA) leases a 100% interest in the Shawville facility. In addition, REMA leases undivided interests in the Keystone and Conemaugh facilities and owns 2,251 MWs of generating facilities. We note that all of the respective leases are obligations of REMA. Accordingly, we respectfully submit that the appropriate disclosure should reflect the lease payment obligations in aggregate and not those of Shawville in isolation. We have reported the aggregate lease payment obligations ($818 million) in Note 10(a), Commitments and Contingencies, Commitments on page F-68.
The expected amount of Shawville’s annual maintenance costs to be incurred during the layup period anticipated to begin in 2015 is currently being refined, but is expected to be small relative to the current fixed operating costs of the facility. As such, we do not consider disclosing the information at this time to be appropriate or necessary to give the reader an adequate understanding of the situation.
16. Litigation and Other Contingencies, page F-85
10. We note that you were not able to “estimate the reasonable amount or range of potential losses” for several of your legal proceedings and contingencies. Where you conclude that you cannot estimate the reasonably possible additional loss or range of loss, please explain to us the procedures you undertake on a quarterly basis to attempt to develop a range of reasonably possible loss for disclosure and, for each material matter, what specific factors are causing the inability to estimate and when you expect those factors to be alleviated. We recognize that there are a number of uncertainties and potential outcomes associated with loss contingencies. However, the disclosures required by ASC 450-20-50-4 do not require you to determine the estimated amount or range of potential additional loss with certainty. An estimate is, by definition, imprecise. An effort should be made to develop estimates for purposes of disclosure, including determining which of the potential outcomes are reasonably possible and what the reasonably possible range of losses would be for those reasonably possible outcomes.
Response: With respect to the matters referred to in the Staff’s comment, GenOn respectfully submits that no reasonably possible losses in excess of accrued amounts were estimable at the time the filing was made or the amounts were not material. The eventual outcome of legal or regulatory proceedings is often difficult to predict, particularly in situations where the proceedings are in the early stages, discovery is incomplete, dispositive motions have not been filed or argued or where the claimant is seeking indeterminate damages. As a consequence, judgments with respect to the outcome, timing and potential loss relating to such proceedings are difficult to make and are subject to risks and uncertainties that could cause actual results to be materially different from those predicted. In accordance with applicable accounting guidance, GenOn establishes accruals for legal and regulatory proceedings when those proceedings present loss contingencies that are both probable and estimable. When we determine that an accrual is not appropriate but we believe a loss is reasonably possible, as well as for proceedings where an accrued liability has been established but for which an exposure to the loss in excess of the amount accrued is reasonably possible, we provide a current estimate of the range of possible loss if such determination can be made and is material or indicate that an estimate of the range of possible loss cannot be made. Estimated ranges of possible loss are based on currently available
information and actual results may vary significantly. For proceedings where we are unable to estimate the possible losses or a range of possible loss, we include disclosure regarding the potential magnitude of the claim to the extent possible. For example, we provided disclosure as to why a range of possible loss could not be made for the following matters in our 2011 Form 10-K: (a) Maryland Fly Ash Facilities in Note 16, Litigation and Other Contingencies and (b) Brandywine Storm Damage and Remediation in Note 16, Litigation and Other Contingencies.
To accomplish the foregoing, each quarter the lawyer(s) responsible for handling each lawsuit (threatened or filed) or regulatory proceeding is requested to analyze the matter to determine whether or not an accrual is appropriate based on whether an unfavorable outcome is “remote,” “reasonably possible” or “probable.” In conducting that analysis the lawyer(s) will consider factors including (i) the nature of the claim, (ii) the procedural status of the matter, if applicable, (iii) the probability or likelihood of success in prosecuting or defending the claim, (iv) the specificity, or lack thereof, regarding the claim, (v) the information available with respect to the claim, (vi) the opinions or views of outside defense counsel and other advisors, and (vii) past experience in similar matters and the experience of others in factually- and legally-similar cases. In most instances, unless and until a matter has advanced to a sufficient state that the legal and factual basis for the claim is well understood it is not possible to determine whether an adverse outcome is probable or reasonably possible and what the reasonably possible range of outcomes would be. Moreover, it is also not possible to determine when the factual and/or legal basis for the claim will be sufficiently well understood since each matter is unique, progresses at its own pace and must stand on its own merits. It is for this reason that such matters are reviewed quarterly to determine what, if any, matters have developed to a sufficient point where a determination of whether an adverse outcome is probable or reasonably possible.
GenOn undertakes specific quarterly procedures to estimate any possible loss, or range of loss, or to determine that such an estimate cannot be made. Representatives from the legal group meet each quarter to discuss and assess various outstanding claims. This assessment includes a consideration of the facts and circumstances of each matter as well as whether a specific dollar claim has been made. Following this meeting a meeting is held with the accounting group to review and discuss all pending and threatened litigation and regulatory matters. Finally, each quarter management conducts two disclosure committee meetings after the quarter close, and prior to the filing of the applicable periodic report, attended by representatives of all major corporate functions. As part of these meetings, outstanding litigation and various other potential contingencies are discussed and assessed. As a result of this process, GenOn believes that it has a process in place to estimate any loss or range of loss, or to determine that such estimate cannot be made. The appropriate disclosures in GenOn’s periodic reports are updated based on the information provided in these meetings.
11. We note that the state of Texas issued a franchise tax assessment against you indicating an underpayment of franchise tax of $70 million. We further note that you accrued only a portion of this liability since you are protesting the entire assessment and are currently in the administrative appeals process. Please tell us how you determined the amount accrued for this matter. To the extent it is reasonably possible you will incur losses in excess of the accrued amount, please disclose the amount or range of reasonably possible losses in excess of amounts accrued as required by ASC 450-20-50.
Response: The amount of the accrued liability subject to ASC 450 was based on a probability weighting of expected outcomes for multiple issues included in the assessment. The $70 million is the total amount, including interest that could result in a loss provided all issues assessed by the
state of Texas were upheld in the appeals process. The amount in excess of the accrued liability that meets the reasonably possible loss standard ranges from $0 to $4 million and is not considered material to our consolidated financial statements.
The Company acknowledges that:
· The Company is responsible for the adequacy and accuracy of the disclosure in the filing;
· Staff comments or changes to disclosure in response to Staff comments do not foreclose the Commission from taking any action with respect to the filing; and
· The Company may not assert Staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.
Please do not hesitate to call me on 832-357-7522 with any questions regarding the foregoing.
| Very truly yours, |
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| /s/ THOMAS C. LIVENGOOD |
| Thomas C. Livengood |
| Senior Vice President and Controller |
cc: J. William Holden, III, Executive Vice President and Chief Financial Officer, GenOn Energy, Inc.